ML20005G822
| ML20005G822 | |
| Person / Time | |
|---|---|
| Site: | Byron  |
| Issue date: | 01/16/1990 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20005G820 | List: |
| References | |
| 50-454-89-21-01, 50-454-89-21-1, 50-455-89-24, NUDOCS 9001230142 | |
| Download: ML20005G822 (15) | |
See also: IR 05000454/1989021
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U.S. NUCLEAR REGULATORY COMMISSION
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REGION III
Reports No. 50.-454/89021(DRP);50-455/89024(DRP)
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Docket Nos. 50-454; 50-455
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Licensee: Commonwealth Edison Company
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Post Office Box 767
Chicago, IL 60690
Facility Name: Byron Station, Units 1 and 2
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' Inspection At: Byron Site, Byron, Illinois
Inspection Conductedi November 18 through December 30, 1989
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-Inspectors: ~ W. J. Krop )
R. N. Sutp11n
J. M. Jacobson
' Approved By: Brent Clayton, Chief
Reactor Projects Section IA
Date
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Inspection Summary
' Ins)ection from November 18 through December 30, 1989 (Reports No. 50-454/89021
_ IDR));50-455/89024(DRP))
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. Areas Inspected: Routine, unannounced safety inspection by the resident
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inspectors of actions on previous inspection findings, operational safety,
reactor startup,-onsite event follow-up, degraded / nonconforming equipment,
- current material-condition, radiation protection controls, maintenance
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activities,-surveillances, cold weather preparation, engineering / technical
. support, security, and Tl 2515/104.
Results: No repetitive concerns were identified that indicated potential
weaknesses during the inspection. The licensee continued to be aggressive
in the resolution of technical issues identified during plant operations.
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'However, the licensee management needs to re-emphasize the importance of
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Ladequate reviews of design / technical information furnished by offsite
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engineering organizations. There have been two recent examples where
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. technical information furstished by.offsite engineering organizations was
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either incomplete or inadequate.
The licensee's performance in maintenance /
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surveillance continues to be good with few problems noted.
However,
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housekeeping during.this inspection period deteriorated from the status
noted in other inspections.
Increased management attention is needed prior
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'to the scheduled Unit I refuel outage from January to March 1990, to ensure
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the plant enters the outage in the best possible housekeeping condition.
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One violation was issued in the area of maintenance, as a result of an
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unresolved item in this area, that pertained to mixed greases in environ-
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mentally qualified Limitorque motor operated valves, being upgraded to a
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violation.- Since, the licensee had taken action to correct and prevent
recurrence of the violation, no response was required.
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DETAILS
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1.
Persons Contacted
Commonwealth Edison Company (Ceco)
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- R. Pleniewicz, Station Manager
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- R. Ward, Technical. Superintendent
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- J. Kudalis, Service Director
D. Brindle, Operating Engineer, Administration
T. Didier, Operating Engineer, Unit 0
T. Gierich, Operating Engineer, Unit 2
T. Higgins,' Assistant Superintendent, Operating
J. Schrock, Operating Engineer, Unit 1
- K. Schwartz, Production Superintendent
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D. St. Clair, Assistant Superintendent, Work Planning
- T. Tulon, Assistant Superintendent, Maintenance
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- D. Winchester, Quality Assurance Superintendent
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- D. Wozniak, ENC Project Manager
- E. Zittle, Regulatory Assurance Staff
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- Denotes those attending the exit interview conducted on January 2,
1990.
The inspectors also had discussions with other licensee employees,
including members of the technical and engineering staffs, reactor
and auxiliary operators, shift engineers and foremen, and electrical,
mechanical and instrument maintenance personnel, and contract security
personnel.~
2.
ActiononPreviousInspectionFindings(92701&92702)
a.
(Closed)OpenItem(454/89017-03(DRP);455/89019-03(DRP)):
Inconsistencies have been noted by the inspectors that warrant
evaluation of the licensee's arocess for assessing degraded /
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. nonconforming equipment. Furter discussion is included in
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Section 3.d of this report.
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b.
(Closed)UnresolvedItem(454/89017-04(DRP);455/890019-04(DRP)):
Improper grease in Limitorque gearcase operators for motor operated
valves (MOVs) used in environmentally qualified (EQ) applications.
-(This unresolved item was originally identified in Inspection Reports
.454/89017; 455/89019 as item 454/89017-01; 455/89019-01).
Closure of
this item was based on the issuance of a violation and is further
discussed in Section 4.b of this report.
c.
(Closed)OpenItem(454/89019-01(DRP);455/89021-01(DRP)):
check valves failing open due to binding.
Further discussion is
included in Section 5.b of this report.
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Plant Operations
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Unit 1 operated at power levels up to 100% for the entire report period.
Presently, Unit 1 is in coastdown in preparation for a refueling outage
scheduled to begin on January 5,1990.
Unit 2 commenced.startup on November 21, 1989, from a forced outage
and has operated at power levels up to 100% for the remainder of the
report period.
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a.
Operational Safety (71707)
During the inspection period, the inspectors verified that the
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facility was being operated in conformance with the licenses
and regulatory requirements and the licensee's management
responsibilities were effectively carried out for safe operation.
Verification was based on routine direct observation of activities
and equipment performance, tours of the facility, interviews and
discussions with licensee personnel, independent verification of
safety system status and limiting conditions for operation action
requirements (LC0ARs), corrective action, and review of facility
records.
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On a sampling basis the inspectors daily verified proper control
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room staffing and access, operator behavior, and coordination of
plant activities with ongoing control room operations; verified
operator adherence with the latest revisions of procedures for
ongoing activities; verified operation as required by Technical
Specifications (TS); including compliance with LC0ARs, with
emphasis on engineered safety features (ESF) and ESF electrical
alignment'and valve positions; monitored instrumentation recorder
traces and duplicate channels for abnormalities; verified status
of various lit annunciators for operator understanding, off-normal
condition, and compensatory actions; examined nuclear instrumenta-
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tion (NI) and other protection channels for proper oaerability;
reviewed radiation monitors and stack monitors for aanormal
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conditions; verified that onsite and offsite power was available
as required; observed the frequency of plant / control room visits
by the station manager, superintendents, assistant operations
superintendent, and other managers; and observed the Safety
Parameter Display System (SPDS) for operability.
No problems
were noted.
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b.
ReactorStartup(71707)
On November 13, 1989, Unit 2 was shut down due to a steam leak
at the inlet flange of pressurizer safety valve, 2RY8010C. On
November 20, 1989, after completion of repairs, the licensee
comenced a Unit 2 reactor startup. The startup was aborted when
control room personnel noted that the estimated critical position
(ECP) for the control rods appeared to be in error.
The ECP had
been calculated, in accordance with procedure BGP 100-7T3, at 52
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steps ~ on control bank "D" with a boron concentration of 747 ppm.
The administrative tolerance level for the ECP was plus or minus
500 pcm for the final critical rod position. Therefore, the
lower limit of the administrative tolerance level was 220 steps
on control bank "C" and the upper limit was calculated at 140
steps en control bank "D".
With shutdown bank ' rods fully withdrawn and the source range at
407 counts per second (cps), the Reactor Operator (RO) withdrew
control bank "A" to 115 steps and the station's nuclear engineers
obtained Inverse Count Rate Ratio (ICRR) data. Control bank "A"
was next stopped at 228 steps (control bank "B" at 113 steps) to
check for criticality and to obtain ICRR data. The next hold point
was either the rod insertion limit (RIL), (control bank "B" at 162
steps and control bank "C" at 47 steps), or the 8 fold count rate
(3256 cps). Due to the time delay involved with the source range
scaler timer and the extremely high differential rod worth of
= control; bank "C" at 40 steps, the rods were withdrawn to the RIL,
several steps past the rod position that would have provided the
8 fold count rate. The R0 checked for criticality at the RIL.
The source range counts were 4600 cps. At this
startup .the Shift Control Room Engineer (SCRE) point in the
instructed the
R0 to insert control bank "C" to the 8 fold count rate which was
determinedtobe38 steps (3170 cps). The station's nuclear
engineers determined from both the ICRR and 8 fold plots that
predicted criticality would have occurred between 50 to 55 steps
on control bank "C".
Therefore, criticality had not been achieved.
However, due to the considerable differences between the conoitions
observed and those predicted (plus 900 pcm) and with the projected
criticality close to RIL, the SCRE decided to re-insert all control
rods and borate.
Further review of data by the station's nuclear engineers determined
that the power history used to determine the ECP did not properly
reflect the last known steady state operation.
However, even with
the correct steady state power history, the revised ECP still
indicated a difference of approximately 480 pcm from the critical
position based on the 8 fold prediction. The station's nuclear
engineers requested assistance from corporate's Nuclear Fuel
Services (NFS).
NFS indicated that the 480 pcm difference could
have possibly been caused by previous reduced power operation that
resulted in a large distortion in the axial power shape from that
assumed in the core design process. The anomalous power shape
would not have been evident during power operation. However, at
power levels below the point of adding nuclear heat, the asymmetry
could cause a delta flux up to 50%. Since the worth of control
rods was proportioned to the square of the local flux, a small
change in the axial power shape could greatly influence the shape
of the differential rod worth curves. The NFS's position on the
possible cause of the 480 pcm error was preliminary and a final
position will be issued later. Therefore, until the licensee and
the NRC have reviewed the final position on the source of the
480pcmdifference}.thismatterisconsideredanopenitem
(455/89024-01(DRP)
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The inspectors did not consider the initial startup activities,
observed on November 20, 1989 on Ur.it 2, as representative of
Byron Station's past performance during reactor startups. This
was communicated to the licensee.
As a result, the licensee
established additional administrative controls to be in place
prior to another startup attempt on Unit 2.
These conditions
were:
Establish a new temporary administrative limit of plus or
minus 750 pcm.
(The new limit was within the Technical
Specification limit of 1000 pcm.)
If the limit was exceeded
the startup wculd be aborted.
Hold points were to be established at least every 50 steps
before the 8 fold count rate was reached and every 10 steps
thereaf ter to obtain ICRR data until criticality was achieved.
An operator aid was to be utilized by the Nuclear Station
Operator (NS0) manipulating the controls and an NSO was to
be stationed at the source range panels. The operator aid
was to identify the predicted critical rod position, the plus
or minus 750 pcm rod position limits, and the 8 fold count
rate.
Establish a new ECP (calculation) hased on conditions other
than the previously used reactor conditions at shutdown
(e.g. last steady state power conditions).
Conduct a control room briefing between the Operating Engineer,
Nuclear Engineer and operating shift prior to pulling control
rods.
On November 21, 1989, at 7:23 p.m., a second Unit 2 startup was
commenced with the above administrative controls in place. The
resident inspectors were in the control room to monitor the
licensee's activities. The ECP was calculated as 150 steps on
control bank "D".
The boron concentration at startup was 839
ppm. At 8:35 p.m. the reactor achieved criticality at 50 steps
on control bank "D".
The difference between the ECP (150 steps)
versus the actual rod position at criticality (50 steps) was
a aproximately the 480 pcm difference that was identified during
tie initial startup aborted on November 20, 1989.
The resident
inspectors concluded that the additional controls established
resulted in an approach to criticality that was commensurate
with good opertting practices.
c.
Onsite Event Follow-up (93702)
(1) On December 12, 1989, at 11:42 a.m. an attempt to start the
Unit 1B Condensate / Condensate Booster (CD/CB) pump for a
return to service after maintenance activities resulted in
a fire in the pump motor. The station's fire brigade was
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activated and dispatched to the pump room to extinguish the
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fire.LAnUnusual, Event (UE)wasdeclaredat11:58a.m.,-
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-when the Shift Engineer ascertained that the fire was not
completely extinguished. 'The licensee's GSEP program required
a UE to be des.lared when a fire can not be extinguished within
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10 tinutes of the arrival of the station's-fire brigade at the
scene of the fire. At 12:07 p.m., the supervisor at the fire
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scene informed the Unit 1 NSO that the fire was stable and-
only smoke was observed coming from the pump motor. At the
time'of the fire, Unit I was in Mode'l at 94% power.
While isolating electrical power to the CD/CB pump motor, a
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breaker-for the auxiliary oil pressure switch for the running
1A CD/CB pump was opened by mistake. As a result, the 1A
CD/CB pump tripped off on low lube oil pressure. The operators
initiated immediate corrective action and enterea abnormal
procedure, 1 BOA SEC-1, " Condensate /Feedwater Malfunction."
The control room personnel response was timely and effective
and a Unit I reactor trip was avoided. The fire was declared-
out at-12:35 p.m. and the UE was terminated. The licensee
has not completed the investigation into the cause of the fire
or the. subsequent inadvertent trip of the 1A CD/CB pump.
Preliminary investigation by the licensee revealed that the
cooling fan mounting for the pum) motor had only one bolt out
of six. The licensee suspects t1at the cooling fan or fan
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bolts could have become loose and damaged insulation on the
motor windings. The resident inspectors will monitor the
licensee's root cause anal
Deviation Report (LER/DVR)ysis via the Licensee Event Report /
process. The inspectors concluded
.that the licensee's fire brigade response was quick and
effective. The licensee plans to convene a team to assess
the activities associated with the fire for possible lessons
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learned.
(2) On November 14,-1989, while attempting to place the 2B
Residual Heat Removal (RHR) pump in'the shutdown cooling
mode, the NSO observed the motor amp (erage (amps) fluctuating
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in the " red zone" of the amp meter 56-70 amps) and tripped
the pump. The licensee initiated an investigation and
determined that the 2B RHR pump sustained bearing and
impeller damage and required repair. The licensee's root
cause investigation has focused on two possible causes,
either foreign material or air in the suction piping caused
the pump damage. The licensee has written but has not yet
closed the DVR that pertains to the event. The licensee
considers air in the 2B RHR suction pipe to the reactor hot
legs as the most probable cause. This was based on the damage
observed when the 2B RHR pump was disassembled for repair.
Also, the 2B RHR pump was taken out-of-service in August
1989 to replace bearings when Unit 2 was in Mode 1.
This
maintenance activity required the 2B RHR system to be drained
prior to initiating maintenance work, and filled and vented
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after maintenance activities were completed.
Even though
station operating procedures for' filling and venting the.RHR
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systems were applicable for Mode 1, the licensee has
preliminarily concluded-that the fill and. vent process was
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not totally effective. The resident inspectors will review
theDVR(6-2-89-081) that documents: this event, for the
licensee's final conclusions.
The 2B RHR pump would have initially performed if called upon
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for a safety injection since the piping that was suspected of-
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air entrainment was only associated with.the shutdown cooling
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- mode and hot leg-recirculation which occurs several days after-
a loss of coolant accident. Prior to the amp fluctuations,
- the NSO had the'2B RHR pump on recirculation with no problems
noted. Only :after opening the suction valves, 2SIO02A(B),-
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from the reactor hot legs, did the anomaly with the amps occur.
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The inspectors. reviewed the activities and documentation
associated with this event and did not identify any possible
causes other than the potential causes identified by the-
licensee.: However, the inspectors did identify-that the. Unit
2 control' room log was-not complete for the time period of
August 5-7, 1989, when the 28-RHR pump was 00S for bearing
replacement. The log did not-identify when some of the
fillingandventingactivities(B0P-RH4)occurredsuchas,
the starting and stopping of the 2B RHR pump. However, the
shift engineer's log did identify some of the activities.
The resident inspectors have not identified previous problems
with the control room logs. This area will be closely
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monitored in future inspections. Discussions with the plant
manager determined that the station was currently reviewing
the requirements for the control room and shift engineer logs
for possible improvement in content.
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d.-
Degraded / Nonconforming Equipment
In a. letter to NRC Region III, dated December 14, 1989, the
licensee identified the actions that had been taken to effectively
assess degraded equipment in a timely manner. The licensee stated
that the operating engineers and at least one Assistant Technical
Staff Supervisor shall have meetings to discuss safety significant
off-normal equipment, or operations, on an as needed basis.
Nuclear Work Requests (NWRs) that have been written for degraded
equipment, unusual out-of-service configurations or abnormal valve
lineup were examples of off-normal conditions identified by the
licensee. The purpose of the meetings is to accomplish a timely
review of off-normal items whose existence may cause an operability
concern.
Based on these discussions, the licensee stated further
review and/or actions may be implemented as required using existing
programs. The inspectors have reviewed the licensee's response
and considers the process described ie the response as an acceptable
method for assessing degraded / nonconforming equipment. The resident
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inspectors considers _this area of plant operations, assessing
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degraded equipment for operability, as one of the key factors for
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successful safe plant operations; therefore, the effectiveness of
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this. method will be closely monitored in future inspections.
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CurrentMaterialConditions(71707)-
.The inspectors performed general plant as well as selected system
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and component walkdowns to assess the general and specific material
condition of-the plant, to verify that NWRs had been initiated for
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. identified equipment problems, and to evaluate housekeeping.
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Walkdowns included an assessment of the buildings; components,-
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and systems for ~ proper identification and tagging, accessibility,
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fire and security door integrity, scaffolding, radiological
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controls, and any unusual conditions.
Unusual conditions included
but were not-limited to water, oil, or other liquids on the ficor
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or equipment; indications of leakage through ceiling, walls or
floors; loose insulation; corrosion; excessive noise; unusual
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temperatures; and abnormal ventilation and lighting.
Results were
as follows:
(l') Material condition of the diesel driven fire pump was improved
by the licensee. The material condition of the pump was
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identified as needing improvement in Inspection Report
454/89017; 455/89019.
(2)- Scaffolds were noted in several areas with the scaffold tags
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expired.
(3) - General housekeeping has deteriorated and increased management
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attention is required. During tours of the plant, the inspectors
.have noted ladders stored behind switchgears, areas without
lighting, and bolts not properly stored or identified prior to
installation.
(4)- Inspectors did not identify any significant material
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deficiencies and the hardware material condition of the
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plant was considered above average for this report period.
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f.
Radiation Protection Controls
The inspectors verified that personnel were following health physics
procedures for dosimetry, protective clothing, frisking, posting,
etc., and randomly examined radiation protection instrumentation for
use, operability, ar.d calibration.
The licensee continues to be aggressive in the resolution of technical
issues identified during plant operations. The licensee's performance in
plant operations during this inspection period was acceptable. However,
increased management attention is required in the area of housekeeping,
especially since Unit I will be in a 59 day refueling outage commencing
on January 5,1990.
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MaintenanceActivities--(62703)
Station maintenance-activities affecting the safety-related and
' associated systems and components- listed below were observed or
reviewed to ascertain that activities were conducted in accordance
' with approved procedures, regulatory' guides and industry codes or
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standards, and in conformance with Technical Specifications.
The folloWint items were considered during the review:
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limiting conditions for operation were met while components or
-systems were removed from and restored to service; approvals were
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-obtained prior to initiating-the work; activities were accomplished
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using approved procedures and were inspected as applicable;
functional testing and/or calibrations were performed prior to
returning components or systems to service; quality control records
were' maintained; activities were accomplished by qualified personnel;
- parts and materials used were properly certified; radiological
controis were implemented; and fire prevention controls were
implemented. Work requests were reviewed to determine the status
of outstanding jobs and to assure that priority was assigned to
safety-related equipment maintenance that could affect system
. performance.
Portions of the following maintenance activities were observed
and/or. reviewed:
NWR'D 67612 - Repair pipe cap.
NWR B 68853 - Disassemble the 28 RHR pump and motor.
NWR B 68996 - Inspect the 2B RHR pump and motor.
NWR B 69530 - Add time delay to 1A Essential Service Water Pump
circuitry.
NWR B 72342 - Repair leak in 1C Feedwater pump recirculation line.
NWR B 72344 - Change grease in coupling on Unit 2 diesel driven AFW
pump.
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The inspectors periodically monitored the licensee's work in
progress and verified the work was performed in accordance with
proper procedures,,and approved work packages, that 10 CFR 50.59 and
other applicable drawing updates were made and/or planned, and that
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operator training was conducted in a reasonabic period of time.
The inspectors reviewed the licensee's maintenance activities
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associated with the forced outage of November 13-21, 1989. The
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forced outage had been caused by a steam leak on the inlet flange to
pressurizer safety valve 2RY-8010C. During this eight day outage,
the maintenance department completed 83 NWRs that included five main
control board distractions.
The licensee had recently initiated a
Pre-bythorized Work (PAW) program.
The program consisted of NWRs
that had already been approved by appropriate station personnel and
were immediately available for the Shift Engineer to initiate the
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Lwork in case of a forced outage. During the Unit 2 ei
outage all identified Unit 2 PAW NWRs were completed (ght day) forced
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17 NWRs . The
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PAW program was different_than other' forced outage lists since the-
- NWRs had already been approved.
In the past, the licensee determined
that NWRs on a forced outage list were useful in the identification
of priority work, however, the process of obtaining authorization for
work was hindering the commencement of work, in a timely manner, and-
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clittle' work was accomplished early in a forced outage.
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b. .
Mixed and Wrong Greases in Limitorque 0)erations
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Based on the September 8,1989, system Materials Analysis Department
'(SMAD) test results, the licensee had initiated action to sample
greases in all EQ MOVs that had a history of maintenance since the
gearcase grease was originally tested by SMAD in the 1984-1985 time
frame. The number of MOVs in this- category were 37 for Unit 1, 'of'
which 11 were inside containment; and 45 in Unit 2, of which 8 were-
.inside containment. Except for four MOVs in Unit I containment;
all' EQ MOVs that were in the suspect category have been sampled.
-The four MOVs in the Unit 1 containment will be sampled during the
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Unit 1 refuel outage that-is scheduled to commence on January 5,
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1990. The following is a summary of the mixed grease issue:
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(1) SMAD report, M-5825-88, dated January 6,1989, reported on
results of grease samples submitted for analysis on November 25,
1988. OneMOV(ISI88048)wasidentifiedwithmixedgrease(20:1
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ratio) and MOV (2SI8814) had the wrong grease (lithium based
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- versus calcium based). The SMAD report was not distributed to
the' station's EQ coordinator and a Deviation Report was.not
issued as a result of these two unsatisfactory test results.
Valve actuators for valves.1SI8814 and 2SI8804B were disassembled
and re-greased on February 8,1989 and July 28, 1989, respectively.
(2) In August 1989, the resident inspectors questioned the overall
EQ implications of the SMAD test results on MOVs ISI8804B and
2 SIB 814. The licensee verified that the SMAD test results
reported on in report M-5825-88 had not been distributed to and
evaluated by the appropriate station personnel. Also, based on
these test results, and the fact that the grease could not be
re-sampled for verification of original test sample results,
(grease had already been changed for ISI8804B and 2SI8814), the
licensee decided to obtain grease samples from an additional 18
(3) SMAD report M-494-89, dated September 8, 1989, identified that
one of the additional 18 MOVs sampled had the wrong grease.
Based on this SMAD test result and the other January 1989 test
results, the licensee decided to sample the grease in all EQ
N0Vs that were subjected to maintenance activities subsequent
to the SMAD grease tests conducted in the 1984-1985 time frame.
(4) Subsequent SHAD test reports M-5038-89 and M-5039-89 identified
valves ICV 112C, ICV 8100 and ICV 8355A with heavy mixed greases.
On November 13, 1989, the licensee performed an On-Site Review
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-forjustificationforcontinuedoperation(JCO)forthevalves.
The.JC0 is.further discussed in Section 5 of this report.
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Even-though the licensee conducted an extensive sampling program to
ascer.tain the status of the type of grease in suspect EQ MOVs, there
was a failure to originally establish adequate measures to ensure
grease discrepancies with EQ M0Vs were identified on DVRs. The
. lack of the-identification of grease discrepancies on DVRs also
contributed to the lack of a timely review by cognizant-operating.
and. technical' staff personnel for operability of valves 1S18804B
and 2S18814. The lack of adequate measures to identify discrepant
_greasesamples-isaviolationof.10CFR50})AppendixB, Criterion
XVI.
(454/89021-01(DRP);455/89024-02(DRP
Other examples of
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failure to have adequate measures for identification of
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discrepancies has not been previously identified by the resident
inspectors. Therefore, the violation described appears to be an
isolated occurrence. This area will continue to be monitored by
the' resident inspectors.
Corrective actions initiated by the licensee in response to this
event include the following:
licensee initiated the necessary NWRs to ensure the MOVs with
mixed or wrong greases were changed to the correct grease.
Procedures BFP FP-28, " Inspection of Limitorque Main Gear Case
Lubrication, BAP 370-2, " Station Sampling Program and BAP
370-2T2, " Sample Variation Report" have been revised to require
the Fuel Handling Department to notify the Shift Engineer of
any' potential discrepancies identified during sampling. BAP
370-2T2 will be processed through the Shift Engineer and
Operating Engineer. This process would provide opportunity for
appro)riate station personnel to review the discrepancy for
possi>1e impact on MOV operability, consistent with the
licensee's response to open item 454/89017-03; 455/89019-03
described in Section 3.d of this report.
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SMAD was contacted to request a revision to the distribution
of test restits to include the station's EQ Coordinator.
Station personnel performed an extensive review of SMAD
analysis reports, completed work history and NWR records and
identified suspect EQ MOVs. These suspect EQ MOVs had the
gearcase grease sampled and analysed to verify that proper
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grease was used.
c.
Surveillance (61726)
The inspectors observed or reviewed surveillance tests required by
Technical Specifications during the inspection period and verified
that tests were performed in accordance with adequate procedures,
that test instrumentation was calibrated, that limiting conditions
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for operation were met, that removal and restoration of the affected
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- components- were accomplished, that results conformed with Tegffical
Specifications and procedure requirements and were reviewed by
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_ personnel _ other than the individual directing the test, and that
any deficiencies identified during the. tests were properly
reviewed'and resolved by appropriate. management personnel.
The inspectors witnessed or reviewed portions of the following
activities:
b,
O BOS XFT-A1,
" Cold Weather Preparation"
12 BOS 2.4.1 a-1,
" Quadrant Power Tilt Ratio Calculation."
1 BOS 3.1.1-2,
" Calorimetric Calculation Daily Surveillance."
1 BOS 3.1.1-21,-
" Train B Solid State Protection. System
Bi-Monthly Surveillance."
1 BOS 8.1.1.2 a-1,
" Unit 1 - 1A Diesel Generator Operability
Monthly."
"
1 BVS 3.1.1-4,.
- Incore-Excore Axial Flux Comparison Monthly
Surveillance."
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1 BVS 3.3.2-l',
" Moveable Incore Detectors Operability Check."
2-BOS 5.2.b-1,
"ECCS Venting and Valve Alignment Monthly
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Surveillance."
2 BOS'7.3.2. a-1,
" Component Cooling Water Pump Operability
Monthly Surveillance."
2 BOS 8.1.1.2. a-2,
" Unit Two - 2B Diesel Generator Operability
Monthly (Staggered) and Semi-Annual
(Staggered). Surveillance."
2 BVS 0.5-2.A.F.1-1, " Auxiliary Feedwater Valve Indication / Stroke
Test (TrainA)."
2 BVS 4.6.2.2-1,
" Reactor Coolant System Pressure Isolation
Valve Leakage and Cold Leg Injection-Isolation
Valve Surveillance."
"
During the inspection perico documented in Inspection Report
454/89014;-455/89016, the inspectors identified several concerns
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in the licensee's surveillance program. The inspectors reviewed
- the status of these concerns with the following results
Monthly surveillance tests for diesel generators (DGs) now verify
the capability of each fuel oil transfer pump to supply the DG
day tank when the DGs were fully loaded.
The inspectors have not identified any further instances were the
licensee has improved the status of degraded subsystems
immediately prior to a surveillance.
The inspectors reviewed surveillance procedure, IBOS 3.3.5-1,
" Remote Shutdown Instrumentation Monthly Surveillance", and
determined that channel checks were accomplished, documented and
appeared effective.
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id. .'ColdWeatherPreparations(71714)
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The inspectors reviewed the licensee's preparations for cold
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weather. The 11censee'has a surveillance, OBOS XFT-A1, Revision 4,
" Freezing Temperature Equipment Protection", that was performed
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between September 28 and November 6, 1989. The surveillance
. verified that normal' cold weather precautions were in place. Some
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of systems / components verified for proper' cold weather precautions
included:' Circulating Water Pump House, Reactor Water Storage
,
~ Tanks, Condensate Storage Tanks, Essential Service Cooling Tower
Valve Rooms, and the Security Diesel. . Verification activities
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- included thermostat settings, energization of heat trace, heater . .
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. power energized and anti-freeze in heaters. No problems were noted.
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One violation was identified.
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5.
Engineering &TechnicalSupport(37700)
- a.
Justification'for Continued Operation
On November:13,.1989, the licensee identified three EQ valves,
(ICV 1120,!1CV8100 and ICV 8355A) with mixed greases. Since the
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mixed greases were contrary to the EQ requirements identified for
Limitorque MOVs, the licensee performed a justification for
continued operation (JCO) on November'13, 1989. The JC0 was written
by-the licensee's corporate PWR Systems Design Group and an On-Site
Review (OSR),89-259, was performed by station personnel. The
inspectors reviewed 0SR 89-259 and determined that the justification
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utilized was inadequate. The JC0 had referenced a licensee letter
to NRR (S. C. Hunsader to T. E. Murley)-submitted on August 26, 1988,
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that stated technical reasons.for the acceptance of EQ MOVs with
mixed greases. On October 6 1988, a letter from NRR to the licensee
(S. P. Sands to H. E. Bliss), stated that'the NRC staff concluded
there was-. insufficient information contained in the licensee's
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August 28, 1988 letter. Since OSR 89-259 did not contain cther
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justifications that could have been utilized by the licensee, such
.as redundant isolation ca) abilities, the inspectors considered the
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-JC0 inadequate. On Novem)er 17, 1989, the licensee-performed
0SR,89-268, to document another JC0 for valves ICV 112C, ICV 8100 and
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1CV8355A. The inspectors reviewed OSR 89-268 and determined that
attachment B adequately addressed JCOs for the three valves with
mixed greases.
The licensee committed to change out the grease
prior to the Unit I startup from the refueling outage scheduled to
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commence January 5,1990.
The inspectors also identified in Inspection Report 455/89017;
455/89019 a problem with a design calculation from an offsite
engineering organization that was utilized to assess operability
of one of the Unit I diesel auxiliary feedwater pump nickel cadium
batteries.
Based on the inadequate JC0 for the MOVs with mixed
greases and the inadequate design calculation just discussed,
licensee's management needs to re-emphasize the importance of adequate
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treviews of design / technical information furnished by offsite
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engineering organizations prior to use in JCOs or On-Site reviews.
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b.
Binding'of Feedwater Checkvalves
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During the-Unit 2 November 13-21 forced outage, boroscope
inspections of the-disc portion of_ feedwater-(FW) check valves
2FWO79-A, B, C, and D were performed. The inspection was' performed
after all four valves were recently found in_ the stuck open position
-at the Braidwood Sation. The inspection determined that feedwater
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check valve 2FWO79B was stuck in the partially open position and
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the valve.was subsequently repaired prior to startup from the~ forced
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outage.'
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.The 2FWO79 valves incorporate a dash-pot assembly design to prevent
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the valve from slamming shut on reverse flow. A review of the valve
design disclosed that the manganese bronze guide bushing for the
. stainless steel. piston rod, a component of the dash-pot assembly,
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may prevent the' valve from operating due to thermal expansion.-
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Apparently, different coefficients of thermal expansion between the
piston rod, bushing, and the valve bonnet, result in deformation of
the guide bushing. . Creep properties of the bushing material at the
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. valve's operating temperature (440 degrees F), resulted in stress
. relieving the bushing at the deformed dimensions. Subsequent cooling-
results in the bushing to piston rod effective clearance becoming
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negative. This causes an . interference fit at low position. Reheating
of-theLyalve. allows the bushing to expand, thus releasing the bound
piston' rod.
A review of the valve manufacturer's tolerances indicated that a
potentially unfavorable " stacking" of tolerances between the bonnet,
bushing, and piston rod, coupled with the difference'in material
properties ~, would.cause the bushing to bind the piston rod.
Laboratory measurements of the parts from one of the' failed valves
at Braidwood,- supported this failure scenario.
If the original
tolerances are not " stacked" unfavorably, adequate clearance over
the range of. operating.tcmperatures would permit normal valve
operation. The. valves that were found in the closed position upon
cool-down-(2FWO79 A, C, and D) were considered operable.
A review of dimension tolerances and valve operating temperatures
indicated that a valve manufactured with unfavorable " stacked"
. tolerances would only be subjected to sticking during low power
(0-20%) operation. As a result, Station Special Operating Orders
were issued to cover low power operations. These orders include the
close monitoring of FW temperatures and expeditiously moving through
FW temperatures below 250 degrees F.
Additionally the licensee has
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committed to inspect all FWO79 check valves, and establish optimum
clearances, where appropriate, during the next outage of sufficient
duration.
No violation or deviations were identified.
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Security (81064)
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The inspectors, by sampling, verified that persons in the protected area
- (PA) displayed proper badges and had escorts if required; vital' areas
were kept. locked and alarmed, or guards posted if required; and personnel
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.'and packages entering the PA received proper search and/or monitoring.
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7.1'TI 2515/104
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.(Closed) Temporary Instruction (TI) 2515/104: Inspection of initial
training for fitness for duty (FFD). On December 20, 1989'the inspector-
attended ~ FFD. training sessions for general employees,. supervisors, and
personnel that could perform escort duties. . Some of the subjects
addressed in the training sessions were:
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- a. General Employees
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(1)
methods utilized to im)lement 10 CFR 26
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(2)-
hazards associated wit.1 the abuse of drugs and misuse of
alcohol.
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(3)
the effect of prescription drugs and over-the-counter drugs
on job performance.
(4).
the consequences from lack of adherence to the policy.
b.
Supervisors.
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same material as the general employees
responsibilities as supervisors
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role of other personnel such as the. Medical Review Officer.
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techniques for recognizing drugs,
behavioral observation techniques
The training sessions lasted approximately three hours. The presentation
media utilized-included slides, videos, and lectures. The medical staff
was present to assist in the answering of any questions.
8.
Open Items
0)en items are matters which have been discussed with the licensee,
w11ch will be reviewed by the inspector and which involve some action
on the part of the NRC or licensee or both. An Open Item disclosed
during the inspection is discussed in Paragraph 3.b.
9.
Exit Meeting (30703)
-The. inspectors met with the licensee representatives denoted in
paragraph I during the inspection period on January 2,1990. The
inspectors summarized the scope and results of the inspection and
discussed the likely content of this inspection report. The licensee
acknowledged the information and did not indicate that any of the
information disclosed during the inspection could be considered
proprietary in nature.
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